In the drilling and production of oil and gas wells, it is typical to prepare a well bore in a target oil or gas-bearing formation using a drill string which is terminated by a drill bit. The drill string is rotated to remove formation ahead of the drill bit, to drill and thus form a wellbore, and to increase the depth of the well. The drill string has an axial throughbore throughout its length which provides a fluid circulation path through the string and BHA and back up the annulus around the string within the well bore.
Drilling mud or other fluid is pumped through the drill string to cool the drill bit, and to aid the passage of drill cuttings from the base of the well to the surface, via an annulus formed between the drill string and the wall of the well bore.
At fixed intervals, typically the drill bit is removed from the wellbore and a casing comprising lengths of tubular casing sections coupled together end-to-end is run into the drilled wellbore and cemented in place. A smaller dimension drill bit is then inserted through the cased wellbore, to drill through the formation below the cased portion, to thereby extend the depth of the well. A smaller diameter casing is then installed in the extended portion of the wellbore and also cemented in place. If required, a liner comprising similar tubular sections coupled together end-to-end may be installed in the well, coupled to and extending from the final casing section. Once the desired full depth has been achieved, the drill string is removed from the well and then a work string is run-in to clean the well. Once the well has been cleaned out, the walls of the tubular members forming the casing/liner are free of debris so that when screens, packers, gravel pack assemblies, liner hangers or other completion equipment is inserted into the well, an efficient seal can be achieved between these devices and the casing/liner wall.
It is important to determine whether there are any cracks, gaps or other irregularities in the lining of a well bore, or in the cement between tubulars which line a well bore, which may allow the ingress of well bore fluid into the annulus of the bore. It is also important that any irregularities in the well bore casing connections and cement bonds are identified and monitored to prevent contamination of the well bore contents.
It is normally difficult to determine whether there are any irregularities in the well bore casing connections and cement bonds as the hydrostatic pressure created by drilling fluid within the well bore prevents well bore fluid from entering the annulus of the bore. In order to overcome this difficulty it is known to the art to use downhole packers to seal off sections of a pre-formed well bore in order to test the integrity of the particular section of bore. One test carried out to identify any such irregularities is a so-called “in-flow” or “negative” test.
During an in-flow test a packer is included on a work string and run into a bore. The individual packer elements of the packer tool are expanded to seal the annulus between the well tubing (casing or lining) and tool in the well bore. Expansion or “setting” of the packer is usually achieved by rotating the tool relative to the work string and the set packer thereafter prevents the normal flow of drilling fluid in the annulus between the work string and well bore tubular. A lower density fluid is then circulated within the work string which reduces the hydrostatic pressure within the pipe. As a consequence of the drop in hydrostatic pressure, well bore fluid can flow through any cracks or irregularities in the lining of the well bore or over the top of the liner lap into the annulus of the bore. If this occurs, the flow of well bore fluid into the bore results in an increase in pressure which can be monitored. As a result it is possible to locate areas where fluid can pass into the well bore through irregularities in the structure of the bore and where repair of the cement or lining may be required. After testing, the bore may be “pressured up” to remove the well bore fluid from the bore and a heavy drilling fluid can be passed through the string to return the hydrostatic pressure to normal.
Typically, a separate trip is required to be made into the well to perform an in-flow or negative pressure test. This is because the conventional packer tools used are set by a relative rotation within the well bore. As many other tools are activated by rotation and indeed as the drill string itself would normally be rotated during this type of operation, it is likely that the packer would prematurely set. This problem has been overcome by the introduction of a weight-set packer. Such a weight-set packer, also referred to as a “compression-set packer”, is disclosed in the Applicant's International Patent Application, publication number WO/0183938, now U.S. Pat. No. 6,896,064, which is hereby incorporated by reference. The packer is set by a sleeve moveable on a body of the packer being set down on a formation in the well bore. Movement of the sleeve compresses one or more packing elements to provide a seal.
This compression-set packer is particularly suitable for integrity testing of a liner when a permanent packer, or ‘tieback’ packer, with a Polished Bore Receptacle (PBR) has been used. Once the permanent packer with the PBR has been set, a single trip can be made into the well to operate clean-up tools and perform an in-flow or negative test. The clean-up tools may be operated by relative rotation of the work string in the well-bore and further the work string can be slackened off so that the sleeve of the compression-set packer lands out on the PBR. This sets the compression-set packer above the PBR and seals the bore between the packers.
An in-flow or negative test can then be performed. Whereas such a negative test involves a “draw down” or reduced pressure effect upon the area of test e.g. a liner top to test the integrity of the cement seal, it may in certain instances instead be required to conduct a positive test which involves the application of high fluid pressure within the lower annulus, the effect of which could be to lift the packer required for conducting the test. In the case of a weight-set or compression packer, there may be insufficient drill pipe weight in the string to resist the high pressures developed during a positive test.